The Maryland Public Service Commission tends not to fund utility projects in the future through rate increases in the present.
But utilities ask for them anyway, saying that such requests are designed to finance much-needed upgrades and maintenance project.
At a time of increasing concerns that infrastructure needs such as aging pipelines and transmission lines are being ignored, utilities say they still have been able to address their most pressing concerns. But they also warn that they need advance financing approval to do much of this work, approval that regulators historically have been reluctant to authorize.
It’s difficult to say what utilities would do if they didn’t have to worry about obtaining financing retroactively through rate increase requests, said Ratanak Heng, a reliability and maintenance engineer at BGE. But as the energy companies await approval of these investments, their customers continue to demand better service.
“Power is more valuable right now than it was five years ago,” he said. “The gauge is always moving.”
Baltimore Gas and Electric Co. and Potomac Electric Power Co. have each requested increases in the rates they charge customers four times in the past five years. Their requests are based on a variety of expenses incurred, including cash working capital for day-to-day use, pensions, severance and even the expenses associated with rate cases themselves.
But a big part of those requests are for improvements to their systems that are made for reliability and safety purposes.
In its most recent request to the Public Service Commission, BGE asked for a revenue increase of $117.6 million for electric and $67.6 million for gas. Of the adjustments that led to this request, a large portion were related to reliability and safety improvements.
“As customers rely more on technology … the standard or expectation is always increasing,” said Heng. “We’re always constantly looking for areas of improvement.”
Utilities in Maryland are regulated by the Public Service Commission. Customer’s energy providers are dictated by where they live, so they cannot rely on competition between utilities to keep costs down. Instead, the commission is tasked with approving any rate, so these companies do not take advantage of their monopolies.
The commission tends not to approve portions of rate increases that account for future costs — they want to see that the investment has been made.
But that system can be problematical, some said.
“The utilities are not going to go out there and spend that money until they know it’s going to be covered,” said Charles Fishman, an energy analyst at Morningstar. “It’s a little bit of a Catch-22.”
In a 2013 report card, the American Society of Civil Engineers found the utility industry lagging behind on infrastructure upgrades. Noting that the nation is dependent on an “aging electrical grid and pipeline distribution systems, some of which originated in the 1880s,” the report noted that weather events and limited maintenance had contributed to an increasing number of power outages. The society bestowed a D-plus grade for the entire energy sector infrastructure.
In Maryland, the typical rate increase order from the Public Service Commission includes a summary, discussion and conclusion on each individual element of the request. That includes adjustments for reliability and safety projects.
In BGE’s most recently decided rate case, the commission in December granted two out of three rate base adjustments for safety and reliability.
In Pepco’s most recent order, the commission decided earlier this month that it would approve two out of four adjustments for reliability. That was on the condition that the company make additional adjustments related to those changes in order to comply with tax law.
For both companies, the adjustments that were not approved covered estimated impacts of planned projects or projected investments. The Public Service Commission made clear in rejecting those changes that it did so because the adjustments did not reflect “actual spending” and were not “known and measurable.”
“Typically you think that the commission is going to grant something less” than is requested, said Mark Case, vice president of strategy and regulatory affairs for BGE.
So the company continues to invest in its systems, in hopes that it will be reimbursed later. But that may not be sustainable, said Case.
“It’s like getting a new roof for your home and saying you’re going to pay the roofing contractor two years later,” he said.
For BGE, improvement priorities include a number of long-term projects. Heng said the company’s priorities fall into six main categories: distribution feeder improvements, better restoration times, distribution automation, replacing aging infrastructure, undergrounding select power lines and managing vegetation.
Pepco declined to go into detail about its reliability improvement goals. According to the 2013 annual report by its parent company, Pepco Holdings Inc., the company has been working to move forward with a $1 billion underground line project in partnership with the District of Columbia Department of Transportation. That project is intended to make those lines far less vulnerable in extreme weather.
That partnership will help with the cost of the project, but it will still require an investment from Pepco. And undergrounding is not necessarily the end-all-be-all of reliability projects.
“As we make investments, we also need to adjust rates to recover those investments,” said Courtney Nogas, a spokesperson for Pepco, in an email statement. “Without that, our ability to continue making improvements will become limited or more costly. No company can continue to function efficiently if earnings decrease over a long period.”
There was an instance for both companies when the commission granted a surcharge for future investments. But it only allowed projects it considered to be cost-effective.
Pepco requested a grid resiliency charge as a part of the rate case it filed in 2012. It asked for a surcharge that would allow three projects that totaled $192 million. The commission allowed one of those projects for a total of $24 million.
When BGE made its own surcharge request, it detailed eight projects totally $136 million. The commission approved four in full and one more in part, for a total of $72.6 million investments over five years.
These types of surcharges were recommended by the state’s Grid Resiliency Task Force, which was born out of concern following outages from major storms. Those events inspired some change, but not everyone remembered the impact, said Heng.
“One of the challenges that I guess a lot of the utilities experience is there is a lag between the investments and the weather incidents that occur that caused the outages to occur,” he said. “When you fast forward to a milder year … customers don’t always remember.”